Today’s blog on widening AECO differentials is a followup to last night’s blog “NGTL’s USJR Outages to Impact Q2/Q3 Production, Lack of New Q4 Capacity Expected To Push Back H1 IPOs” {LINK]. NGTL outages impact AECO differentials and we expect to see AECO differentials hurt (widen) this summer with the NGTL outages highlighted in our blog last night. But we remind that the recent widening AECO differential is also impacted by other factors ie. REX Zone 3 expansion.

AECO differentials have widened in the past few months. There are a multitude of factors that impact AECO prices relative to HH. But we believe two of the key factors were the NGTL outages in Nov/Dec 2016, and the startup of REX Zone 3 expansion in early Jan. The below graph shows the HH less AECO differentials in US$ since Oct 1, and it shows how HH has dramatically outperformed ie. the differential widened.

NGTL’s Dec forecast for ~1.8 bcf/d outage on parts of their system in Aug should gain attention as producers reflect outages in guidance. The bigger issue for investors is the lack of new egress capacity in Nov/Dec, which is likely to cause many expected H1/17 Montney IPOs to be delayed until they have visible egress for growth..

Our research writes each month on the NGTL monthly outage forecast. The NGTL system is the Alberta natural gas pipeline system within TransCanada. The NGTL Dec monthly outage forecast [LINK] was when we first saw a new planned ~1.8 bcf/d outage in Q3/17. This was generally overlooked as it came out just before Xmas. Our weekly Energy Tidbits memo (Dec 25, 2016 memo) highlighted this with an item “Big NGTL curtailments in Q3/17 and Q2/17”. We further wrote “This week, TCPL/NGTL posted its “NGTL & Foothills Systems Monthly Outage Forecast December”, which is their customer update on receipt capacity by pipeline. This is essentially a warning report on where receipt capacity is lower than normal, hence where there will likely be gas curtailments. The primary focus for our review is the receipt capacity on Upstream James River Receipt Area of NGTL, which is the part of the NGTL system that has the biggest impact on the Montney, Duvernay and other multi zone Cretaceous sands. The good news is that the system is running full this winter. The bad news is that there are some very big curtailments coming in Q2/17 and even moreso in Q3/17. NGTL estimates curtailments to hit 0.8 bcf/d in Q2, and ~1.8 bcf/d in Q3/17. It is also important to note that NGTL says the Q3/17 curtailments will impact both interruptible and firm transportation.” The Aug outage of ~1.8 bcf/d is 20% of the then 9.2 bcf/d capacity Upstream James River (USGR) Receipt. The below NGTL map shows the USGR receipt area.

WTI ended down $1.10 to $51.38/b after the late morning disclosure by OPEC on higher Dec oil production volumes. OPEC’ reported that its OPEC members estimate for Dec oil production was up ~60,000 b/d, instead of down 221,000 b/d as estimated by 3rd parties. It also means that OPEC will need to make bigger cuts to get to its targeted 32.5 million b/d effective Jan 1. OPEC compliance is the most important near term oil price factor. The higher Dec production and big variance to 3rd party estimates is likely to move more to the sidelines until the next OPEC MOMR comes out on Feb 13 showing what OPEC members saying they produced in Jan.

OPEC members reported Dec production was up ~60,000 b/d. OPEC released its Monthly Oil Market Report (MOMR) Jan 2017 this morning, which includes OPEC’s Dec 2016 oi production by country as provided by “Direct Communications” (ie. provided directly by OPEC members) and also by “Secondary Sources” (ie. Platts, EIA, etc). OPEC members Gabon, Libya, Iran and Qatar did not provide Dec production estimates. But the remaining 9 OPEC members (Algeria, Angola, Ecuador, Iraq, Kuwait, Nigeria, Saudi Arabia, UAE and Venezuela) estimated Dec oil production was ~60,000 b/d higher than Nov. Using Secondary Sources for Gabon and Libya (these countries do not report monthly data directly to OPEC) and Iran and Qatar being flat in Dec to their Nov estimates, then total OPEC production in Dec was 34.358 million b/d, up 83,000 b/d from 34.275 million b/d in Nov.

The slightly negative tone to oil prices (WTI trading down $0.90/b as of 7am mountain time) this morning is being driven by the first indications that the major US shale/tight oil basins are returning to growth with the EIA’s estimate that major shale/tight oil production is higher in Jan and Feb to make three consecutive months of increasing oil production. Plus there is an increasing inventory of DUCs to support further 2017 oil growth. We say slightly negative because this growth is expected with the increasing US oil rig count, plus the reality that biggest near term factor on oil prices is the OPEC and non-OPEC production cuts of 1.731 million b/d effective Jan 1. Oil prices should continue to bounce around current levels until we see data in early Feb on the compliance to the cuts.

The strength of US shale/tight oil was seen in yesterday afternoon’s EIA (US Energy Information Administration) monthly Drilling Productivity Report Jan 2017 (DPR), which is the EIA’s estimate of the current and next month (in this case Jan and Feb) production for the major shale/tight basins, and its estimate of DUCs (Drilled UnCompleted Wells) as at the end of the just completed month (in this case Dec).

Cdn heavy oil prices are off to a strong start in Jan with differentials narrowing by ~US$2.50/b so far in Jan, and this is before the OPEC cuts lower medium/heavy deliveries to the US. This strong start to Cdn heavy oil prices in Jan has been overshadowed by last week’s announcement of BC’s conditional approval of the Trans Mountain expansion (see our Jan 12 blog [LINK]) that should provide support to Cdn heavy oil prices post 2019.

As expected, Cdn heavy oil is benefiting in 2017 with a better (lower) differential for WCS less WTI. The below Bloomberg graph shows that , since Jan 1, the WTI discount to WTI has narrowed by ~US$2.50/b. WCS is Western Canada Select, the marker price for heavy sour Cdn blended oil with a nominal API gravity of 20.5 and sulfur content of 3.4%.

It was a good day for Canadian heavy oil producers with the late afternoon announcement that the BC government gave conditional approval of the Trans Mountain expansion. This sets up the potential for the new Line 2 to potentially start in late 2019 and moving 540,000 b/d of heavy oil. The BC approval follows the Govt of Canada late Nov conditional approval and the NEB late May conditional approval.

The Trans Mountain expansion is essentially a twinning of the existing pipeline that will increase capacity from its current 300,000 b/d to 890,000 b/d. With the expansion, Line 1 will move to a capacity of 350,000 b/d, and would expected to be used for refined products and light oil, but could potentially shift to heavy oil depending on demand. Whereas Line 2 would have a capacity of 540,000 b/d and would be allocated to heavy oil.

Did you know that only 0.4% of the Jan 1, 2017 TSX oil and gas dividend payers by way of market capitalization have a yield of 4% or greater? Did you know that the 4% or greater yield players now represent $10 billion market capitalization, down 94% from $171 billion of market capitalization in Jan 2015?

I know I didn’t. Luckily for me, I have the advantage of the Stream team to make my research broader and better. I wrote last week’s blog on Russia’s hacking including to support the anti-fracking movement following a comment from Aaron Bunting (Principal, CFO). And today’s blog came because Ryan Dunfield (President, Managing Principal) came in my office and asked me these yield questions. Once I got over the shock of the data, it was time to write this blog.

Yesterday’s CIA/FBI/NSA report clearly noted the primary Russian cyber attack was on the hacking and leaking of actual emails. But the report also reminded that cyber risks come from much more than hacking and leaking actual emails. Or more than our primary focus for energy – a cyber sabotage of energy infrastructure like a refinery, pipeline, or an electricity grid. Or more than forcing a computer system off line to cause service disruptions of a service. Rather the report reminded that cyber risks also include providing false/misleading/slanted “content” from programming, media, social posting, etc. Basically the good old days of disinformation are back, but spread in today’s connected world and with a purpose/objective in mind.

The purpose of our blogs and our separately published weekly Energy Tidbits report is to help our Stream partners with perspective on events/developments impacting energy and oil and gas. They are normally data driven. Today’s blog is different than normal. It doesn’t’ have specific data on oil production, or OPEC quotas, or emissions. So it may not seem to be as relevant to oil and gas. But we think it is because it speaks to how “content” is being used to try to impact political or a populist change, which we have all seen has a direct and significant impact on oil and gas. The big surprises for global markets and oil and gas in the past year were changes that markets did not expect – Brexit and a Trump win. And also in Canada with big impact on oil and gas from the NDP majority win in Alberta and the Liberal majority win in Canada.

The Trump inauguration is two weeks away. Our Nov 9, 2016 blog “Piecing Together Trump’s Oil And Gas Impact” [LINK] was our analysis of Trump’s statements/plans/commitments with respect to oil and gas, including his ambitious 100 day action plan “Donald J. Trump’s Contract With The American Voter” [LINK]. We highlighted a number of points including Canadian heavy oil was positioned to benefit if Trump can reduce or eliminate, over time, imports from OPEC.

ExxonMobil CEO Rex Tillerson’s pick as Secretary of State reminded us that Trump’s natural gas priority should add more support for strong mid term natural gas prices.